1. Field of the Invention
The present invention generally relates to oil and gas well (borehole) logging tools, and more particularly to an improved method of determining fluid holdup values by adjusting holdup measurements using complementary measurements which quantify smaller component (hydrocarbon) inclusions.
2. Description of the Related Art
In the production of underground petroleum products (oil and gas), it is important to determine the fractions of flow through a wellbore that are attributed to different components, that is, oil, water and gas. For example, it is known that water production often increases as oil reserves are depleted, or in response to a water injection program. When the degree of water present in the production flow becomes excessive, production logging surveys are used to determine the locations and rates of water entry into the flow regime. These surveys include both measurements of flow rate and attempts at determining the average density of the well fluid at various survey depths.
Various methods have been devised to calculate the fractional percentages, or "holdups," of a phase component in the fluid flow. One of the most common techniques involves the measurement of gamma ray attenuation to determine bulk density of the fluid. See, e.g., U.S. Pat. Nos. 4,939,362 and 5,012,091. In U.S. Pat. No. 5,359,195, a casing is used to shield surrounding formations from the gamma radiation so that the detector response is primarily governed by mixed phase fluids flowing in the well. In another technique described in U.S. Pat. No. 4,441,361, the multiphase fluid is blended into a mixture and directed past a rotor assembly to measure the flow rate; gamma ray attenuation is also measured to determine average density, and this information is used along with derived data for densities of individual phases to determine volumetric fractions of the fluid phases as related to the total flow regime.
There are many limitations to the use of gamma rays in determining fluid holdups. Consequently, this technique is often combined with other techniques, such as gradiomanometry (measuring differential pressure) and water-holdup measurements using capacitive or dielectric tools. For example, U.S. Pat. No. 5,361,632 teaches the use of a temperature compensated gradiomanometer to measure average fluid density, and gamma ray attenuation to calculate holdup fractions of the fluid; the flow rates for individual phases are determined using a flowmeter, and multiplying each holdup fraction by the total flow rate.
One problem that arises in measuring fluid holdups occurs when the water holdup becomes so high that the water phase becomes essentially continuous. In this case, such as a flow of a mixture of oil or gas and water with the oil or gas dispersed as bubbles in a continuous water medium, the high conductivity of the water masks varying dielectric effects that are attributable to the changes in the volumetric fraction of the oil or gas included within the mixture.
Another problem occurs in that only the dielectric constant of the central portion of the well is measured. Very often flow will vary across a section of the well, especially in highly deviated or horizontal wells, where the fluid flow may become stratified across a cross-sectional area of the borehole. This flow pattern may result in prior art fluid holdup tools detecting only a small portion of the stratified flow, such as only in one phase, and not the other portions of the flow of produced fluids. Further, different flow patterns may be present both in vertical flow and horizontal flow. In horizontal flow, bubble flow and elongated bubble flow often will occur. Additionally, stratified flow, wave flow, slug flow, annular and annular mist flow, and dispersed froth flow may occur for horizontal flow depending upon different flow parameters and flow velocities. Vertical flow patterns may also include bubble flow, froth flow, annular and annular mist flow, and slug flow. Furthermore, different densities, frictional parameters, and different phases for different constituents of segregated multiphase fluid flow result in different flow rates for the different constituents. For example, in a segregated multiphase flow in a producing well having flow constituents which consist of oil, gas and water, the gas phase may flow faster than the oil phase, which may flow faster than a water phase. In fact, in some sections of wells having multiple production zones, one phase may flow in an opposite direction within the well to that of a new flow of fluids.
Some attempts have been made to overcome the limitations of prior art methods that rely solely upon center-sampling holdup measurements, such as by utilizing a combination of center sample and fullbore gas holdup measurements. As discussed in U.S. Pat. No. 5,552,598, the downhole flow regime in a horizontal well borehole (i.e., annular or stratified flow) is determined based on a first gas holdup value measured with a fluid density tool and a second gas holdup value measured with a fullbore gas holdup tool. A different approach is disclosed in U.S. Pat. No. 5,531,112, which determines fluid holdups using a production logging tool that measures the velocity profile of multiphase fluid flow within a cross-section of a well. The tool has rotating arms with flow sensors at the tips to measure flow at different localized regions, which allows detection of variations in fluid properties attributable to flow constituents. The result is more accurate determination of holdup values. See also U.S. Pat. No. 5,631,413 which discloses a similar holdup tool and flow meter.
The foregoing techniques still suffer certain limitations. In particular, measurements of conductivity made with the sampling technique of the '598 and '413 patents are deficient in their ability to accurately measure certain water/hydrocarbon holdups. This deficiency arises because fluids that are sheared to dimensions smaller than the sensor probe tips will not be measured by the device. In other words, the probe tips tend to retain a water film when traversing these small hydrocarbon inclusions. Thus, droplets or bubbles whose diameters are smaller than that of the probe tip, e.g., 1.02 mm (0.04"), are typically not detected. In fact, inclusions must probably have a diameter of 1.27 (0.05") or larger to be seen by the probes. This problem is especially prevalent with oil/water measurements wherein the water is relatively clean and the oil is heavy, and when high multi-component flow velocities yield more finely subdivided flow geometries. It would, therefore, be desirable to devise an improved method of measuring fluid holdups in a well borehole that compensated for small, non-detectable inclusions. It would be further advantageous if the method did not require new instrumentation, but rather relied on conventional measurements, so as to avoid adding extra complexity and expense to the borehole equipment.